Downhole lift gas injection system

ABSTRACT

A downhole lift gas injection valve is retrievably connected to a downhole hanger device from which a lift gas injection conduit is suspended within a production tubing of a hydrocarbon fluid production well, wherein the valve receives the lift gas from an annular space surrounding the tubing via a side inlet in the production tubing and a tubular packer device is retrievably connected to an upper end of the hanger device to seal the side inlet from a space in the production tubing above the packer device.

FIELD OF THE INVENTION

The present invention relates to a downhole lift gas injection system. The system can be used downhole in a wellbore for enhancing the production of hydrocarbons, such as oil, gas and condensate.

BACKGROUND OF THE INVENTION

A wellbore for the production of hydrocarbons may generally be provided with a production tubing, extending from surface to a hydrocarbon reservoir. The production tubing has a downhole end for inflow of hydrocarbons produced from the reservoir zone. The production tubing may extend through a casing, which may be cemented in the wellbore, leaving an annular space between the production tubing and the casing. A production packer may be arranged near a downhole, lower end of the production tubing to seal the annular space above the packer from fluid pressure below the packer. The pressure typically originates from the reservoir zone.

Produced hydrocarbons flow from the reservoir zone into the wellbore and into the downhole end of the production tubing. From the downhole end, the hydrocarbons flow to surface by virtue of fluid pressure originating from the reservoir zone. However, the fluid pressure in the reservoir zone may decrease over time, due to depletion of the reservoir. The reduced pressure results in a decreased flow rate of produced fluids in the production tubing. In case of a gas well, such decreased flow rate also may be caused by increased water production from the well over time.

In order to improve the flow rate of fluid produced from the wellbore, lift gas can be injected into the stream of produced fluid. The lift gas reduces the fluid column in the production tubing, thereby reducing the weight and the fluid pressure thereof. If the fluid pressure of the fluid column in the wellbore can be reduced below the pressure in the reservoir zone, the remaining gas in the reservoir can be produced. Thus, lift gas can be used to enhance and increase production from the wellbore.

Known lift gas injection systems are disclosed in U.S. Pat. No. 8,631,875 and US patent applications US2003/056958; US2008/271893; US2006/113082 and US2009/255684.

US-2009/0255684-A1 discloses a wellbore system whereby a turn-over suspension mandrel is landed inside a side pocket mandrel. The mandrel is connected to a gas lift valve on one end and to a coil on the opposite end. The turn-over suspension mandrel can be constructed such that gas entering the gas lift valve is directed down through the coil and into the wellbore beneath the production packer.

In the system of US-2009/0255684-A1, the gas lift valve must be retrieved to surface, if and when necessary, together with the turn-over mandrel and coil.

It is an object of the invention to provide an improved wellbore system which overcomes the drawbacks of the prior art and wherein the gas lift valve can be retrieved to surface by a wireline without retrieving the turnover-mandrel and coil.

SUMMARY OF THE INVENTION

The invention provides a downhole lift gas injection system wherein a lift gas injection valve is retrievably arranged in a valve chamber in a downhole hanger device from which a lift gas injection conduit is suspended within a hydrocarbon fluid production tubing, which valve receives the lift gas from an annular space surrounding the tubing via a side inlet in the production tubing and wherein a tubular packer device is retrievably connected to an upper end of the hanger device to seal the side inlet from a space in the production tubing above the packer device.

Suitably the valve chamber is formed in the hanger device in a manner allowing the gas lift valve to be retrieved from the hanger device by upwardly pulling the gas lift valve out of the valve chamber.

In one embodiment the hanger device comprises a cylindrical body provided with a channel that fluidly connects the valve chamber with the lift gas injection conduit. The channel may comprise an axial through bore formed in the cylindrical body, wherein the valve chamber is defined in an upper portion of the through bore.

The side inlet may be formed in a side pocket mandrel included in the production tubing.

Suitably, the packer device may be sealed to the production tubing by a first annular seal, wherein the hanger device is sealed to the production tubing by a second annular seal, and wherein the side inlet is located between the first and second annular seals. The hanger device may be provided with a polished bore receptacle into which the packer device is received. Furthermore, the packer device may be retrievable to surface independently of the hanger device.

Advantageously, in a second mode of operation, the tubular packer device is temporarily removed from the wellbore and a plug is arranged in the hanger device so as to seal a lower internal space of the production tubing from an upper internal space of the production tubing, wherein the side inlet is arranged to allow fluid to be circulated from surface through the annular space, the side inlet and the upper internal space back to surface. The hanger device may be provided with a landing nipple for receiving the plug.

Suitably the hanger device is supported by a hanger profile provided at the inner surface of the production tubing, or by a packer member that is compressed against the inner surface. The packer member may be a retrievable packer member.

The lift gas injection conduit may be provided with a safety valve for isolating the valve chamber from fluid pressure in the wellbore below the hanger device. Furthermore, the lift gas injection conduit may be adapted to receive a closure element to close the lift gas injection conduit. Also, the lift gas injection conduit may be provided with at least one non-return valve for preventing backflow of fluid from the wellbore into the lift gas injection conduit.

According to another aspect, the invention provides a method for enhancing hydrocarbon fluid production using the system as described above.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described hereinafter by way of example in more detail with reference to the accompanying drawings in which:

FIG. 1 shows a cross section of an embodiment of the wellbore system of the invention during a first mode of operation;

FIG. 2 shows a cross section of a wellbore, indicating retrieval of the gas lift valve of the embodiment of FIG. 1;

FIG. 3 shows the embodiment of FIG. 1 in a second mode of operation; and

FIG. 4 shows a cross section of an alternative embodiment of the wellbore system of the invention.

In the description and drawings, like reference numerals relate to like components.

DETAILED DESCRIPTION OF DEPICTED EMBODIMENTS

FIGS. 1 and 2 show a wellbore system 1 during a first mode of operation. A wellbore 2 is formed in an earth formation 3 for the production of hydrocarbon fluid from a reservoir zone 4. A casing 6 is cemented in the wellbore by a layer of cement 8. The wellbore 2 is in fluid communication with the reservoir zone 4 via perforations 10 in the casing and the wellbore wall. A production tubing 12 extends from a wellhead (not shown) at surface through the casing 6 to the reservoir zone 4. Herein, an annular space 14 is formed between the production tubing 12 and the casing 6.

The production tubing 12 has an inlet in the form of open downhole end 16 for inflow of produced hydrocarbon fluid. A production packer 18 is provided between the production tubing 12 and the casing 6 to seal an upper portion 20 of the annular space 14 from the reservoir zone 4. The production tubing 12 is assembled from tubular sections, one of which being a side pocket mandrel 22 having side pocket 24 and side inlet 26.

A hanger device 28 is arranged in the production tubing 12 and supported therein by hanger profile 30 provided at the inner surface of the production tubing 12.

Alternatively the hanger device 28 may be supported in the production tubing 12 by a packer arrangement (not shown) whereby the hanger device includes a retrievable packer, or is supported by a retrievable packer, that is compressed against the inner surface of the production tubing.

The hanger device 28 comprises a cylindrical body 32 sealed to the production tubing 12 by annular seal 34 and provided with a bore 36 and a flow passage 38 for flow of produced hydrocarbon to surface. An upper portion of the bore 36 forms a valve chamber 40 in which a gas lift valve 42 is arranged. The gas lift valve 42 is at the upper end thereof provided with a latch member 44 that may be connected to a latching element 46 on wireline 48 for pulling the gas lift valve 42 out of the valve chamber 40 and retrieval to surface (FIG. 2).

The gas lift valve 42 has an inlet (not shown) that is in fluid communication with the side inlet 26 of the side pocket mandrel 22 via a transverse bore 50 formed in the hanger device 28. The hanger device 28 has a tubular upper portion 51 provided with a polished bore receptacle 54 for receiving a packer device (referred to hereinafter) and a landing nipple 56 for receiving a plug 57 (FIG. 3).

A lift gas injection conduit 58, such as a coiled tubing, is connected to or integrally formed with the lower end of the hanger device 28 and extends through the production tubing 12 to below the inlet 16 thereof. The lift gas injection conduit provides fluid communication between the through bore 36 and the space in the wellbore 2 below the production tubing 12. Further, the lift gas injection conduit 58 is provided with a surface controlled safety valve 60 for selectively isolating the valve chamber 40 from fluid pressure in the wellbore below the hanger device 28, a dart catcher 62 for receiving a dart or similar device to close the lift gas injection conduit 58, and a dual flapper valve 64 for preventing backflow of fluid from the wellbore into the lift gas injection conduit 58 during running in. The safety valve 60 is provided with a pressure gauge (not shown) to monitor fluid pressure in the lift gas injection conduit 58 during retrieval of the hanger device.

A tubular packer device 66 is arranged above the hanger device 28 in the production tubing 12, the packer device 66 being received in the polished bore receptacle 54 of the hanger device 28 and in sealing relationship therewith. An annular seal 68 is provided to seal the packer device 66 to the production tubing 12. An upper portion of the packer device 66 is provided with a landing profile 69 for retrieval of the packer device on wireline to surface.

FIG. 3 shows the wellbore system 1 in a second mode of operation, whereby the packer device 66 is absent and whereby the plug 57 is received in the landing nipple 56. The plug 57 closes the tubular upper portion 51 of the hanger device 28 so as to seal a production zone 70 of the wellbore from an internal space 72 of the production tubing 12 above the hanger device 28. In this mode of operation the side inlet 26 of the side pocket mandrel 22 is in fluid communication with the internal space 72.

FIG. 4 shows an alternative wellbore system 80 that is substantially similar to the wellbore system 1, but with the following differences. The gas lift valve 42 is arranged in the side pocket mandrel 22 in conventional manner. The inlet of the gas lift valve is in fluid communication with the side inlet 26 of the side pocket mandrel 22, and the outlet of the gas lift valve 42 is in fluid communication with the side pocket 24. Furthermore, the wellbore system 80 comprises a hanger device 82 substantially similar to the hanger device 28, except that the hanger device 82 does not have a valve chamber, and that the bore 36 is in fluid communication with the side pocket 24 via transverse bore 50.

During normal operation in the first mode, the hanger device 28 with the lift gas injection conduit 58 connected thereto, is lowered through the production tubing 12 to the hanger profile 30 of the production tubing. The dual flapper valve 64 prevents inflow of wellbore fluid into the lift gas injection conduit 58 during running in. The gas lift valve 42 may be arranged in the valve chamber 40 during lowering, or alternatively a dummy gas lift valve (not shown) may be installed in the valve chamber 40 during lowering.

In a next step the packer device 66 is lowered through the production tubing 12 until it is received in the polished bore receptacle 54 of the hanger device 28.

Production of hydrocarbon fluid from the wellbore 2 is then started whereby a stream of hydrocarbon fluid flows from the reservoir zone 4 via the perforations 10 into the wellbore 2 and into the inlet 16 of the production tubing 12. The stream then flows through the production tubing 12 to surface thereby passing through the flow passage 38 of the hanger device and through the packer device 66.

If over time the reservoir pressure drops due to reservoir depletion, or if the percentage of water in the stream increases, it may be required to inject lift gas into the stream of produced fluid so as to decrease the specific weight thereof. Thereto, lift gas is pumped from surface into the annular space 14, which then flows via side inlet 26, side pocket 24 and transverse bore 50 to the gas lift valve 42. The latter opens at a predetermined pressure difference between the valve inlet and the valve outlet and thereby allows the lift gas to flow via the bore 36 and the lift gas injection conduit 58 into the production zone 70 of the wellbore 2. Thus, the lift gas enters the stream of produced fluid below the inlet 16 of the production tubing 12 and thereby reduces the specific weight of the stream of produced fluid in optimal manner.

When it is required to replace the gas lift valve 42, for example with one having a different activation pressure, or if a dummy gas lift valve is to be replaced by the gas lift valve 42, latching element 46 is lowered into the production tubing 12 on wireline 48 and latched to latch member 44. The gas lift valve 42 or dummy valve is then pulled out of the valve chamber 40 on wireline 48 and retrieved to surface via the lubricator of a conventional Christmas tree (not shown). In this manner it is achieved that the gas lift valve or dummy valve may be retrieved to surface without simultaneously retrieving the lift gas injection conduit 58. The replacement gas lift valve is then lowered on wireline through the production tubing 12 and installed into the valve chamber 40. Instead of installing the replacement gas lift valve in the valve chamber 40, a dart launcher for launching a dart or similar device into the dart catcher 62 may be installed in the valve chamber 40.

The second mode of operation may be applied, for example, when a volume of brine present in the annular space 14 is to be circulated out of the wellbore 2, e.g. when pumping of lift gas through the annular space 14 is started for the first time. In this mode the plug 57 is lowered on wireline through the production tubing 12 until the plug is landed in the landing nipple 56 of the hanger device 28. Thereby the production zone 70 of the wellbore 2 is sealed from the internal space 72 above the hanger device 28. Subsequently the packer device 66 is retrieved to surface using a wireline (not shown) latched to the landing profile 69 of the packer device 66. In this manner the side inlet 26 of the side pocket mandrel 22 is brought in fluid communication with the internal space 72 above the hanger device 28. A stream of gas, for example lift gas, is then pumped from surface into the annular space 14. The stream of gas thereby forces the volume of brine via the side inlet 26 and the internal space 72 of the production tubing 12 out of the wellbore. In a next step the packer device 66 may be re-installed in the production tubing 12 to (re)commence lift gas injection during hydrocarbon fluid production from the wellbore 2.

If it is required to retrieve the hanger device 28 to surface, a dart (not shown) or similar closure device may be installed in the dart catcher 62 so as to close the lift gas injection conduit 58. This may be done by arranging the dart in a dart launcher that is lowered on wireline into the valve chamber 40. Subsequently fluid pressure is applied in the annular space 14 to pump the dart out of the dart launcher and into the dart catcher 62. Thereafter the safety valve 60 may be closed as a precaution. During retrieval of the hanger device 28 on wireline to surface, the fluid pressure in the lift gas injection conduit 58 may be monitored by means of the pressure gauge provided to the safety valve so as to detect any undesired inflow of wellbore fluid into the lift gas injection conduit 58.

Normal operation of the alternative wellbore system 80 (FIG. 4) is substantially similar to normal operation of the wellbore system 1 described above, except regarding the following. The gas lift valve 42 or dummy gas lift valve is installed in the side pocket 24 prior to lowering the packer device 66 into the production tubing 12. Furthermore, if the gas lift valve 42 or dummy gas lift valve needs to be retrieved to surface, the packer device 66 is first retrieved to surface to allow wireline access to the gas lift valve 42 in the side pocket 24.

The present invention is not limited to the above-described embodiments thereof, wherein various modifications are conceivable within the scope of the appended claims. For instance, features of respective embodiments may be combined. 

1. A downhole lift gas injection system, wherein: a lift gas injection valve is retrievably arranged in a valve chamber in a downhole hanger device from which a lift gas injection conduit is suspended within a production tubing of a hydrocarbon fluid production well, the lift gas injection valve receives the lift gas from an annular space surrounding the production tubing via a side inlet in the production tubing; and a tubular packer device is retrievably connected to an upper end of the hanger device to seal the side inlet from a space in the production tubing above the packer device.
 2. The system of claim 1, wherein the hanger device comprises a cylindrical body provided with a channel that connects the valve chamber to the lift gas injection conduit, the channel comprising an axial through bore formed in the cylindrical body, and the valve chamber being defined in an upper portion of the through bore.
 3. The system of claim 1, wherein the tubular packer device is sealed to the production tubing by a first annular seal, the hanger device is sealed to the production tubing by a second annular seal, and wherein the side inlet is located between the first and second annular seals.
 4. The system of claim 3, wherein the hanger device is provided with a polished bore receptacle into which the tubular packer device is received.
 5. The system of claim 1, wherein the tubular packer device is retrievable to surface independently of the hanger device.
 6. The system of claim 1, wherein the gas lift valve is retrievable from the valve chamber by pulling the gas lift valve out of the valve chamber.
 7. The system of claim 1, wherein the valve chamber is formed in an upper portion of the hanger device.
 8. The system of claim 1, wherein the side inlet is formed in a side pocket mandrel included in the production tubing.
 9. The system of claim 1, wherein, in a second mode of operation, the tubular packer device is temporarily removed from the wellbore and a plug is arranged in the hanger device so as to seal a lower internal space of the production tubing from an upper internal space of the production tubing, and wherein the side inlet is arranged to allow fluid to be circulated from surface through the annular space, the side inlet and the upper internal space back to surface.
 10. The system of claim 1, wherein the lift gas injection conduit is provided with a safety valve for isolating the valve chamber from fluid pressure in the wellbore below the hanger device.
 11. The system of claim 1, wherein the lift gas injection conduit is adapted to receive a closure element to close the lift gas injection conduit
 12. The system of claim 1, wherein the lift gas injection conduit is provided with at least one non-return valve for preventing backflow of fluid from the wellbore into the lift gas injection conduit.
 13. A method of production of hydrocarbon fluid from an earth formation comprising flowing a stream of said hydrocarbon fluid to flow from a reservoir zone into a wellbore wherein using the system of claim 1 to enhance the production of hydrocarbon fluid from the earth formation.
 14. A method of production of hydrocarbon fluid from an earth formation comprising: providing a wellbore formed in an earth formation, comprising a casing cemented in the well bore and a production tubing extending from a wellhead through the casing to a reservoir zone; lowering a hanger device with a flow passage, and a lift gas injection conduit connected said hanger device, through the production tubing; after the previous step, lowering a packer device through the production tubing until it is received in a receptacle of the hanger device; flowing a stream of hydrocarbon fluid from the reservoir zone into the wellbore via perforations in the casing, and into an inlet of the production tubing and through the production tubing to the wellhead, thereby passing through the flow passage of the hanger device and through the packer device.
 15. The method of claim 14, whereby preventing inflow of wellbore fluid into the lift gas injection conduit during said lowering of said hanger device.
 16. The method of claim 14, whereby pumping lift gas via the lift gas injection conduit into a production zone of the wellbore whereby said lift gas enters the stream of hydrocarbon fluid below an inlet of the production tubing.
 17. The method of claim 14, wherein the hanger device further comprises a gas lift valve within a valve chamber, and a latch member provided on the gas lift valve, said method further comprising replacing the gas lift valve, comprising: lowering a latching element on a wireline into the production tubing; latching the latching element to said latch member; pulling said gas lift valve out of the valve chamber on said wireline; retrieving the gas lift valve to surface; lowering a replacement gas lift valve through the production tubing; and installing the replacement gas lift valve in the valve chamber. 